None.
Not Applicable.
The invention relates generally to drill bits. More particularly, the invention relates to a drill bit designed to improve the drill bit""s rate of penetration and longevity. Even more particularly, the invention relates to a drill bit having a pilot cutting surface on the drill bit face that extends from a reamer portion on the drill bit face that cuts to the full diameter of the drill bit, the drill bit being further designed to reduce bit vibration and extend longevity.
In drilling a borehole in the earth, such as for the recovery of hydrocarbons or for other applications, it is conventional practice to connect a drill bit on the lower end of an assembly of drill pipe sections which are connected end-to-end so as to form a xe2x80x9cdrill string.xe2x80x9d The drill string is rotated by apparatus that is positioned on a drilling platform located at the surface of the borehole. Such apparatus turns the bit and advances it downward, causing the bit to cut through the formation material by either scrapping, fracturing, or shearing action, or through a combination of all cutting methods. While the bit rotates, drilling fluid is pumped through the drill string and directed out of the drill bit through nozzles that are positioned in the bit face. The drilling fluid cools the bit and flushes cuttings away from the cutting structure and face of the bit. The drilling fluid and cuttings are forced from the bottom of the borehole to the surface through the annulus that is formed between the drill string and the borehole.
Drill bits in general are well known in the art. Such bits include diamond impregnated bits, milled tooth bits, tungsten carbide insert (xe2x80x9cTCIxe2x80x9d) bits, polycrystalline diamond compacts (xe2x80x9cPDCxe2x80x9d) bits, and natural diamond bits. In recent years, the PDC bit has become an industry standard for cutting formations of grossly varying hardnesses. The cutter elements used in such bits are formed of extremely hard materials, which sometimes include a layer of thermally stable polycrystalline (xe2x80x9cTSPxe2x80x9d) material or polycrystalline diamond compacts (xe2x80x9cPDCxe2x80x9d). In the typical PDC bit, each cutter element or assembly comprises an elongate and generally cylindrical support member which is received and secured in a pocket formed in the surface of the bit body. A disk or tablet-shaped, hard cutting layer of polycrystalline diamond is bonded to the exposed end of the support member, which is typically formed of tungsten carbide. The cutting elements or cutting elements are mounted on a rotary bit and oriented so that each PDC engages the rock face at a desired angle. Although such cutter elements historically were round in cross section and included a disk shaped PDC layer forming the cutting face of the element, improvements in manufacturing techniques have made it possible to provide cutter elements having PDC layers formed in other shapes as well.
The selection of the appropriate bit and cutting structure for a given application depends upon many factors. One of the most important of these factors is the type of formation that is to be drilled, and more particularly, the hardness of the formation that will be encountered. Another important consideration is the range of hardnesses that will be encountered when drilling through layers of differing formation hardness. In running a bit, the driller may also consider weight on bit, the weight and type of drilling fluid, and the available or achievable operating regime. Additionally, a desirable characteristic of the bit is that it be xe2x80x9cstablexe2x80x9d and resist vibration.
Depending upon formation hardness, certain combinations of the above-described bit types and cutting structures will work more efficiently and effectively against the formation than others. For example, a milled tooth bit generally drills relatively quickly and effectively in soft formations, such as those typically encountered at shallow depths. By contrast, milled tooth bits are relatively ineffective in hard rock formations as may be encountered at greater depths. For drilling through such hard formations, roller cone bits having TCI cutting structures have proven to be very effective. For certain hard formations, fixed cutter bits having a natural diamond cutting element provide the best combination of penetration rate and durability. In soft to hard formations, fixed cutter bits having a PDC cutting element have been employed with varying degrees of success.
The cost of drilling a borehole is proportional to the length of time it takes to drill the borehole to the desired depth and location. The drilling time, in turn, is greatly affected by the number of times the drill bit must be changed in order to reach the targeted formation. This is because each time the bit is changed, the entire drill string, which may be miles long, must be retrieved from the borehole section by section. Once the drill string has been retrieved and the new bit installed, the bit must be lowered to the bottom of the borehole on the drill string which must be reconstructed again, section by section. As is thus obvious, this process, known as a xe2x80x9ctripxe2x80x9d of the drill string, requires considerable time, effort and expense. Accordingly, it is always desirable to employ drill bits that will drill faster and longer and that are usable over a wider range of differing formation hardnesses.
The length of time that a drill bit is kept in the hole before the drill string must be tripped and the bit changed depends upon a variety of factors. These factors include the bit""s rate of penetration (xe2x80x9cROPxe2x80x9d), its durability or ability to maintain a high or acceptable ROP, and its ability to achieve the objectives outlined by the drilling program. Operational parameters such as weight on bit (WOB) and RPM have a large influence on the bit""s rate of penetration. Weight on bit is defined as the force applied along the longitudinal axis of the drill bit.
A known drill bit is shown in FIG. 1. Bit 10 is a fixed cutter bit, sometimes referred to as a drag bit or PDC bit, and is adapted for drilling through formations of rock to form a borehole. Bit 10 generally includes a bit body having shank 13, and threaded connection or pin 16 for connecting bit 10 to a drill string (not shown) which is employed to rotate the bit for drilling the borehole. Bit 10 further includes a central axis 11 and a cutting structure on the face 14 of the drill bit, preferably including various PDC cutter elements 40. Also shown in FIG. 1 is a gage pad 12, the outer surface of which is at the diameter of the bit and establishes the bit""s size. Thus, a 12xe2x80x3 bit will have the gage pad at approximately 6xe2x80x3 from the center of the bit.
As best shown in FIG. 2, the drill bit body 10 includes a face region 14 and a gage pad region 12 for the drill bit. The face region 14 includes a plurality of cutting elements 40 from a plurality of blades, shown overlapping in rotated profile. Referring still to FIG. 2, bit face 24 may be said to be divided into three portions or regions 25, 26, 27. The most central portion of the face 24 is identified by the reference numeral 25 and may be concave as shown. Adjacent central portion 25 is the shoulder or the upturned curved portion 26. Next to shoulder portion 26 is the gage portion 27, which is the portion of the bit face 24 which defines the diameter or gage of the borehole drilled by bit 10. As will be understood by those skilled in the art, the boundaries of regions 25, 26, 27 are not precisely delineated on bit 10, but instead are approximate and are used to describe better the structure of the drill bit and the distribution of its cutting elements over the bit face 24.
The action of cutting elements 40 drills the borehole while the drill bit body 10 rotates. Downwardly extending flow passages 21 have nozzles or ports 22 disposed at their lowermost ends. Bit 10 includes six such flow passages 21 and nozzles 22. The flow passages 21 are in fluid communication with central bore 17. Together, passages 21 and nozzles 22 serve to distribute drilling fluids around the cutter elements 40 for flushing formation cuttings from the bottom of the borehole and away from the cutting faces 44 of cutter elements 40 when drilling.
Gage pads 12 abut against the sidewall of the borehole during drilling, and may include wear resistant materials such as diamond enhanced inserts (xe2x80x9cDEIxe2x80x9d) and TSP elements. The gage pads can help maintain the size of the borehole by a rubbing action when cutting elements on the face of the drill bit wear slightly under gage. The gage pads 12 also help stabilize the PDC drill bit against vibration.
However, although this general drill bit design has enjoyed success, improvements in bit longevity, rate of penetration and performance are still desired. A faster, longer life drill bit will result in longer runs at lower costs, thus improving operation efficiency.